1. Field of the Disclosure
This disclosure relates generally to subsea well systems for controlling fluid flow there through in response to adverse downhole conditions, including formation fluid influx into the wellbore, commonly referenced to as a kick.
2. Background of the Art
Wellbores or wells are drilled in subsurface formations for the production of hydrocarbons (oil and gas). Subsea wells can extend more than 5,000 ft. below more than 10,000 ft. of water. Wellhead equipment, including blowout preventers (BOPs), kill line, and control modules are utilized at the sea floor for controlling pressure of the fluid in a return annulus between a drill string and a riser (“riser annulus”) or to close the fluid flow through the wellbore (referred to as well shut-in) to prevent blowouts due to influx of fluid from the formation into the annulus between the drill string and the wellbore (“well annulus”) due to higher pressure in the formation than in the wellbore. Such increase in the fluid flow returning from the wellbore to the surface is referred to herein as a “kick.”
Operating companies involved in drilling of deep water wellbores have been experiencing a substantial increase in non-productive rig time (NPT). This is in part due to the uncertainty in the status or function of the subsea BOPs during drilling operations. The majority of this NPT is due to the additional rig time required to retrieve, check, and reinstall the BOP. Also on certain occasions, kicks are either not detected in a timely manner or the control units are not timely activated due to heavy dependence on human interaction at the surface. The first can result in shutting in the well (or killing the well) prematurely and the second in a blowout.
During drilling of a subsea wellbore, a fluid (mixture of water and certain additives) referred to as the “mud” is supplied to the wellbore via a drill string used for drilling the wellbore. The mud returns to the surface via an annulus between the drill string and the wellbore to a point above the BOP and then via an annulus between a riser and the drill string to the surface. The operators attempt to maintain pressure in the wellbore (referred to as the “hydrostatic pressure”) above the pressure inside the formation surrounding the wellbore (referred to as the “formation pressure”) by controlling the weight of the mud column in the wellbore so that the fluid from the formation will not enter into the wellbore, thereby avoiding kicks. In practice, on occasions, the formation pressure does exceed the hydrostatic pressure, causing kicks to occur. If the flow of the fluid due to a kick is successfully controlled, the kick is considered killed. An uncontrolled kick that results in the well unloading mud through the riser is referred to as a “blowout.”
Kicks occur for a variety of reasons that include: (1) insufficient mud weight that exerts less pressure on the formation than the formation pressure; (2) improper hole fill-up during trips e.g. as the drill pipe is pulled out of the hole, the mud level falls but is not filled timely; (3) swabbing i.e. pulling the drill string from the borehole creates a swab pressure (negative pressure) that reduces the effective hydrostatic pressure below the formation pressure; (4) gas-contaminated mud which usually occurs when a fluid from a core being drilled releases gas into the mud, which expands and reduces the hydrostatic pressure; and (5) lost circulation which decreases the hydrostatic pressure due to a shorter mud column.
In the current subsea well systems, a kick is detected from several indicators, some of which are observed at the surface. Each rig crew member typically has the responsibility to recognize and interpret such indicators and take appropriate action. All such indicators, do not positively identify a kick, some merely warn of a potential kick situations. Key warning signs drilling personnel monitor include: (1) flow rate increase, while pumping mud at a constant rate which is interpreted as an influx of the formation fluid; (ii) mud pit volume increase at the rig site; (iii) flow rate measurement proximate to the BOP; (iv) flow of the mud into the mud pit when the surface pumps are shut down; (v) decrease in pump pressure and pump stroke increase due to fluid entering into the borehole that causes the mud to flocculate, causing temporary increase in the pump pressure; (vi) improper hole fill-up when the drill string is pulled out of the hole; and (vii) change in the drill string weight due to low buoyant effect on the drill string when gas enters the wellbore. Such methods involve interpretation of a large amount of data from a control system showing the parameters monitored during drilling. Such systems operate on the principle of containing a kick by closing a combination of BOP rams after interpreting the available data, then using the choke and kill lines to remove the kick. While such systems work in most cases, such systems may not provide timely detection and/or successful closure of the BOP rams around the casing or the drill string. In addition, using a riser for the return fluid can be ineffective because it requires closing and sealing the riser annulus in response to kicks, which in some cases does not occur. Therefore, it is desirable to provide a subsea wellbore system and methods that detect the presence of adverse conditions, such as kicks, in a timely manner, from an integrated set of sensors in addition to human input to take actions in real time or near real time in response to such detection to control the wellhead equipment to alleviate such adverse conditions.
Additionally, it is desirable to provide an alternative system and methods that do not rely on sealing the riser annulus in response to kicks.
The disclosure herein provides a relatively rapid response control system and a system for controlling return fluid flow outside the return path around the drill pipe for more effective control of the pressures due to kicks.